U.S. patent number 7,395,670 [Application Number 11/061,875] was granted by the patent office on 2008-07-08 for gas turbine fuel preparation and introduction method.
This patent grant is currently assigned to Praxair Technology, Inc.. Invention is credited to Raymond Francis Drnevich, Vasilis Papavassiliou.
United States Patent |
7,395,670 |
Drnevich , et al. |
July 8, 2008 |
Gas turbine fuel preparation and introduction method
Abstract
Method of preparing and introducing fuel into the combustors of
a gas turbine in which a hydrocarbon containing feed, oxygen and
steam are introduced into a catalytic partial oxidation reactor to
produce a product stream. The hydrocarbon containing feed contains
no less than about 15 percent by volume on a dry basis of
hydrocarbons with at least two carbon atoms and/or at least about 3
percent by volume of olefins. The reactant mixture formed of the
hydrocarbon containing feed, oxygen and steam has an oxygen to
carbon ratio of between about 0.08 and about 0.25 and a water to
carbon ratio of between about 0.05 to about 0.5. The hydrocarbon
containing feed is introduced into the reactor alone or with a
steam at a temperature no greater than 600.degree. C. and the
product stream is produced at a temperature of between about
600.degree. C. and 860.degree. C. and contains less than about 0.5
percent of olefins and less than 10 percent of hydrocarbons with
two or more carbon atoms on a dry basis. After cooling the product
stream the product stream is introduced into the combustors of the
gas turbine to form part or all of the fuel required to support
combustion.
Inventors: |
Drnevich; Raymond Francis
(Clarence Center, NY), Papavassiliou; Vasilis
(Williamsville, NY) |
Assignee: |
Praxair Technology, Inc.
(Danbury, CT)
|
Family
ID: |
36927888 |
Appl.
No.: |
11/061,875 |
Filed: |
February 18, 2005 |
Current U.S.
Class: |
60/780; 60/777;
60/772 |
Current CPC
Class: |
F02C
9/26 (20130101); F23R 3/286 (20130101); F02C
3/20 (20130101); F02C 7/22 (20130101); F23K
5/002 (20130101); F02C 9/48 (20130101); F23K
2400/10 (20200501); Y02T 50/60 (20130101); F05D
2270/08 (20130101); Y02T 50/677 (20130101); Y02T
50/672 (20130101) |
Current International
Class: |
F02C
6/18 (20060101) |
Field of
Search: |
;60/777,780,39.12,723
;423/650-654 ;252/372 |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
|
|
|
|
|
|
|
953806 |
|
Nov 1999 |
|
EP |
|
9220963 |
|
Nov 1992 |
|
WO |
|
Other References
Huff et al., "Partial Oxidation of Alkanes Over Noble Metal Coated
Monoliths", Catalysis Today 21 (1994) pp. 113-128. cited by other
.
Kramer et al., "Flexible Hydrogen Plant Utilizing Multiple Refinery
Hydrocarbon Streams", NPRA Annual Meeting (1996) pp. 1-17. cited by
other .
Reyes et al., "Evolution Of Processes For Synthesis Gas Production:
Recent Developments In An Old Technology", Ind. Eng. Chem. Res. 42
(2003) pp. 1588-1597. cited by other .
Chlapik et al., "Alternative Lower Cost Feedstock For Hydrogen
Production", NPRA Annual Meeting (2004) pp. 1-8. cited by
other.
|
Primary Examiner: Suhol; Dmitry
Assistant Examiner: Sung; Gerald L
Attorney, Agent or Firm: Rosenblum; David M.
Claims
We claim:
1. A method of preparing and introducing fuel into combustors of a
gas turbine, said method comprising: introducing, into a catalytic
partial oxidation reactor, a hydrocarbon containing feed stream
comprising no less than about 15 percent by volume on a dry basis
of hydrocarbons with at least two carbon atoms and/or at least
about 3 percent by volume of olefins along with an oxygen
containing stream and a steam stream so that a reactant mixture is
obtained within the catalytic partial oxidation reactor, prior to
contact with catalyst, having an oxygen to carbon ratio between
about 0.08 and about 0.25 and a water to carbon ratio of between
about 0.05 and about 0.5; the hydrocarbon containing feed stream
being introduced into the catalytic reactor alone or in combination
with the steam stream at a temperature of no greater than about
600.degree. C.; reacting said reactant mixture within the catalytic
partial oxidation reactor so that a product stream is produced at a
temperature of between about 600.degree. C. and about 860.degree.
C., the product stream having a hydrocarbon content consisting of
methane, less than about 0.5 percent of olefins by volume on a dry
basis, less than about 10 percent of alkanes with two or more
carbon atoms on a dry basis and less than about 1 percent by volume
on a dry basis of hydrocarbons other than methane, alkanes and
olefins and a remaining content comprising hydrogen, carbon
monoxide, carbon dioxide and water vapor; cooling the product
stream; and introducing the product stream into the combustors so
that the product stream constitutes at least part of the fuel
required to support combustion within the combustors.
2. The method of claim 1, wherein said hydrocarbon containing feed
stream is an FCC offgas, a coker offgas, sweet refinery gas, or
coke oven gas.
3. The method of claim 1, wherein a fuel stream is formed by
combining the product stream, as a first fuel stream, with a second
fuel stream, thereby to at least in part cool the product stream by
direct heat exchange.
4. The method of claim 3, further comprising: combining the
hydrocarbon containing feed stream with the steam stream to form a
combined stream; introducing the combined stream into the catalytic
partial oxidation reactor; and indirectly transferring heat from
the product stream to the combined stream, thereby to preheat the
combined stream and to at least in part cool the product
stream.
5. The method of claim 3, further comprising: compressing an air
stream to form the oxygen containing stream; pumping a makeup water
stream to form a pressurized water stream; and quenching the
product stream with the pressurized water stream.
6. The method of claim 3, further comprising producing the steam
stream by pumping a makeup water stream to form a pressurized water
stream and indirectly transferring heat from the product stream to
the pressurized water stream within a heat exchanger, thereby to
cool the product stream and to form the steam stream.
7. The method of claim 6, further comprising forming the oxygen
containing stream by compressing an air stream to form a compressed
air stream and indirectly transferring heat from the product stream
to the compressed air stream, thereby preheating the compressed air
stream and also cooling the product stream.
8. The method of claim 6, wherein the air stream is a bleed air
stream from a compressor section of the gas turbine.
9. The method of claim 3, wherein the second fuel stream is natural
gas.
10. The method of claim 1 or claim 2, wherein said combustors are
lean premix combustors.
11. The method of claim 10, wherein each of said combustor has a
primary mixing zone for mixing a fuel and compressor air to obtain
a combustible mixture, a downstream secondary combustion zone for
combusting the combustible mixture, primary fuel nozzles for
feeding a primary fuel stream, constituting part of the fuel, to
the primary mixing zone and a secondary fuel nozzle for introducing
a secondary fuel stream, constituting a remaining part of the fuel,
into the secondary combustion zone and downstream of the primary
fuel nozzles to stabilize combustion.
12. The method of claim 11, wherein: the product stream contains at
least about 10 percent by volume hydrogen; and the secondary fuel
stream introduced by the secondary fuel nozzle constitutes the
product stream.
13. The method of claim 12, wherein the product stream is cooled
by: pumping a makeup water stream to form a pressurized water
stream; quenching the product stream with the pressurized water
stream; and indirectly transferring heat from the product stream to
the second fuel stream.
14. The method of claim 13, wherein the primary fuel stream is
natural gas.
Description
FIELD OF THE INVENTION
The present invention relates to a method of preparing and
introducing fuel into combustors of a gas turbine. More
particularly, the present invention relates to such a method in
which a hydrocarbon containing feed stream is reacted with steam
and oxygen in a catalytic partial oxidation reactor to reduce the
heavy hydrocarbon content of such stream to acceptable levels prior
to introduction into combustors of a gas turbine.
BACKGROUND OF THE INVENTION
Gas turbines are used in a variety of industrial settings to supply
power to a load, generally an electrical generator. A gas turbine
consists of a compressor to compress air and an expander to recover
energy from the compressed air after having been heated. The
compressed air is heated within a set of combustors located between
the compressor and the expander.
Gas turbines are designed to burn a variety of fuels such as
natural gas, liquefied petroleum gas and synthesis gases containing
hydrogen and carbon monoxide as well as liquid fuels such as #2
fuel oil. Additionally, gases that are produced from steel
production, such as blast furnace gases and coke oven gases are
also utilized. Blast furnace gases are typically blended with other
gases in that they do not have sufficient heating value to be used
alone. Coke oven gases contain too much hydrogen to be used in
connection with lean premix combustion systems.
Coke oven gases can be produced with a high content of hydrocarbons
containing two or more carbon atoms or a high olefin content that
can thermally crack and produce carbon deposits in gas turbine
combustion components. While blending such gases will reduce the
problems associated with thermal cracking, the degree to which such
gases are blended also will act as a limitation on the utilization
of such gases. There are other offgases produced in refineries, for
instance, sweet refinery gases and fluidic catalytic cracker
offgases that similarly contain a high content of hydrocarbons with
two or more carbon atoms and have the potential for thermal
cracking. Similar problems exist in using other types of offgases
and byproducts produced in other chemical production facilities. A
further problem is that the makeup of such gases can vary over time
and as such, their use as gas turbine fuel can be highly
problematical.
As will be discussed, the present invention provides a method in
which fuels are pretreated at a catalytic partial oxidation reactor
to lower the heavy hydrocarbon content of such gases, for example
the hydrocarbons with two or more carbon atoms and/or unacceptably
high olefin contents to acceptable levels so as to be utilized as a
source of fuel for a gas turbine. Moreover, such treatment also
dampens the effect of variability in the consistency of the
hydrocarbon makeup of such gases.
SUMMARY OF THE INVENTION
The present invention provides a method of preparing and
introducing fuel into combustors of the gas turbine. In accordance
with the method, a hydrocarbon containing feed stream is introduced
into a catalytic partial oxidation reactor along with an oxygen
containing stream and a steam stream. The hydrocarbon containing
feed stream comprises no less than about 15 percent by volume in a
dry basis of hydrocarbons with at least two carbon atoms and/or at
least about 3 percent by volume of olefins. The hydrocarbon feed
stream, oxygen containing stream and steam stream are introduced
into the catalytic partial oxidation reactor so that a reaction
mixture is obtained, prior to contact with catalyst, having an
oxygen to carbon ratio of between about 0.08 and about 0.25 and a
water to carbon ratio of between about 0.05 and about 0.5.
The hydrocarbon containing feed stream is introduced into the
catalytic reactor alone or in combination with a steam stream at a
temperature of no greater than about 600.degree. C. The reactant
mixture is reacted within the catalytic partial oxidation reactor
so that a product stream is produced at a temperature of between
about 600.degree. C. and about 860.degree. C. The product stream
has a hydrocarbon content consisting of methane, less than about
0.5 percent of olefins by volume on a dry basis, less than about 10
percent of alkanes with two or more carbon atoms on a dry basis and
a remaining hydrocarbon content of less than about 1.0 percent by
volume on a dry basis of hydrocarbons other than methane, alkanes
and olefins. The remaining content of the product stream comprises
hydrogen, carbon monoxide, carbon dioxide and water vapor. The
product stream is then cooled and introduced into the combustors of
the gas turbine so that the product stream constitutes at least
part of the fuel required to support combustion within the
combustors.
The fuel stream can be formed by combining the product stream, as a
first fuel stream, with a second fuel stream to form a combined
fuel stream and thereby to at least in part cool the product
stream. The second fuel stream can be natural gas.
The hydrocarbon containing feed stream can be combined with the
steam stream to form a combined stream. The combined stream is
introduced into the catalytic partial oxidation reactor to form the
reactant mixture. Heat can be indirectly transferred from the
product stream to the combined stream, thereby to preheat the
combined stream and to at least in part cool the product
stream.
An air stream can be compressed to form the oxygen-containing
stream. A makeup water stream can be pumped to form a pressurized
water stream. The product stream is then quenched with the
pressurized water stream.
The steam stream can be produced by pumping a makeup water stream
to form a pressurized water stream. Heat is indirectly transferred
from the product stream to the pressurized water stream within a
heat exchanger. This cools the product stream and thus, forms the
steam stream. Additionally an oxygen containing stream can be
formed by compressing an air stream, thereby to form a compressed
air stream. Heat is indirectly transferred from the product stream
to the pressurized air stream. This preheats the compressed air
stream and also cools the product stream. The air stream can be a
bleed air stream from a compressor section of the gas turbine.
In any embodiment, the combustors can be lean premix combustors and
each of the lean premix combustors can have a primary mixing zone
for mixing fuel and compressor air to obtain a combustible mixture
and a downstream secondary combustion zone for combusting the
combustible mixture. Each of the lean premix combustors can have
primary fuel nozzles for feeding a primary fuel stream,
constituting part of the fuel, to the primary mixing zone and a
secondary fuel nozzle for introducing a secondary fuel stream,
constituting a remaining part of the fuel, into the secondary
combustion zone and downstream of the primary fuel nozzles to
ensure combustion stability. Where the hydrogen within the product
stream is present in an amount that is at least about 10 percent by
volume, the secondary fuel stream introduced by the secondary fuel
nozzle can constitute the product stream. The product stream can be
cooled by pumping a makeup water stream to form a pressurized water
stream and quenching the product stream with the pressurized water
stream. Heat may also be indirectly transferred from the product
stream to the second fuel stream. The primary fuel stream can be
natural gas.
In any embodiment the hydrocarbon containing feed stream can be an
FCC offgas, a coker offgas, coke oven gas, or a sweet refinery
gas.
BRIEF DESCRIPTION OF THE DRAWINGS
While the specification concludes with claims distinctly pointing
out the subject matter that Applicants regard as their invention,
it is believed that the invention would be better understood when
taken in connection with the accompanying drawings in which:
FIG. 1 is a schematic illustration of an apparatus for carrying out
a method in accordance with the present invention;
FIG. 2 is an alternative embodiment of an apparatus for carrying
out a method in accordance with the present invention;
FIG. 3 is a schematic illustration of a further embodiment of an
apparatus for carrying out a method in accordance with the present
invention;
FIG. 4 is a schematic illustration of a yet further embodiment of
an apparatus for carrying out a method in accordance with the
present invention;
FIG. 5 is a schematic illustration of still, yet further embodiment
of an apparatus for carrying out a method in accordance with the
present invention;
FIG. 6 is a schematic illustration of an embodiment of an apparatus
for carrying out a method in accordance with the present invention
that is connected with the use of a lean premix combustor; and
FIG. 7 is a schematic illustration of a lean premix combustor of
the type that is schematically illustrated in FIG. 6.
DETAILED DESCRIPTION
With reference to FIG. 1 a hydrocarbon containing feed stream 10
("HC Stream") is pretreated in a catalytic partial oxidation
reactor 12 ("CPOX") to produce a product stream 14 that is combined
with a natural gas stream 16 ("NG") or other fuel stream having a
sufficient heating value, to form a fuel stream 18 that is
introduced as fuel to a gas turbine 20.
Gas turbine 20 has a compression section 22 that can be a series of
stages. Compressor section 22 compresses an air stream 24 to form a
compressor air stream 26 that is heated by combustion of fuel
stream 18 in combustors 28 to produce an exhaust stream 30. Exhaust
stream 30 is introduced into a turbine section 32 that is connected
to a load 35 that can be an electrical generator. Compressor
section 22 and expander section 32 are mechanically coupled
together. Combustors 28 can consist of combustors that are arranged
around the compressor section 22 in a manner well known in the art.
Expander 32 can be split into two independent sections. The first
section is on the same shaft as compressor 22 and the second
section is on a second shaft that is connected to load 34.
Hydrocarbon containing feed stream 10 has a hydrocarbon content of
at least 15 percent by volume on a dry basis of hydrocarbons with
two or more hydrocarbons and/or at least about 3 percent by volume
of olefins. For example, such stream could be a refinery offgas
such as a fluidic catalytic cracker offgas, a coker offgas or a
sweet refinery gas. Coke oven gases having a high hydrocarbon
content is another possibility. As mentioned above, such a feed is
unsuitable as a fuel to gas turbine 20 because the hydrocarbon
content has a high potential for carbon cracking. In order to
reduce the aforesaid hydrocarbon content to acceptable levels,
hydrocarbon containing feed stream 10 is introduced into catalytic
partial oxidation reactor 12 along with a steam stream 35 and an
oxygen containing stream 36 to form a reactant mixture within the
catalytic partial oxidation reactor 12 that is in turn contacted
with a catalyst. It is to be noted that hydrocarbon containing feed
stream 10, steam stream 35 and oxygen containing stream are all at
a sufficient pressure to allow for product stream 14 to be produced
at a sufficient pressure for combination with natural gas stream 16
or for introduction alone into combustors 28.
Steam stream 35 is added at a rate of between about 0.05 to about
0.5 water to carbon ratio within the reactant mixture. The ratio of
steam addition is important since it helps with reformation of the
olefins and other hydrocarbons with more than two carbon atoms. Too
much steam is undesirable because excessive steam will also lower
the temperature within catalytic partial oxidation reactor 12 and
thus, prevent the decomposition of the higher order hydrocarbons to
methane, carbon monoxide, hydrogen and etc. In addition, excess
steam will dilute the volumetric fuel content of the product
stream.
Oxygen containing stream 36, which can be air, oxygen enriched air
or other oxygen containing gas is added at a rate of between about
0.08 and about 0.25 oxygen to carbon ratio within the reactant
mixture.
This can be done using a sparger or static mixer or reticulated
metallic or ceramic foam monolith. The foam monolith provides a
tortuous path that can provide safe and complete mixing of the
oxygen at a relatively low pressure drop. The proportions of
hydrocarbon, steam and oxygen can be controlled by controlling the
flow rates of the aforementioned streams by, for example, by
valves, not illustrated.
Hydrocarbon containing feed stream 10 and steam stream 35 are
preferably combined to form a combined stream 38 that is introduced
into catalytic partial oxidation reactor 12 at a temperature of no
greater than 600.degree. C. to prevent cracking of higher order
hydrocarbons. As could be appreciated, the aforesaid streams could
be introduced separately. Although not required, hydrocarbon
containing feed stream 10 can be preheated to conserve oxygen. The
temperature of the exit of catalytic partial oxidation reactor 12
is maintained at between about 600.degree. C. and about 860.degree.
C. to preferentially reduce the content of olefins in the
hydrocarbons with two or more carbon atoms to acceptable levels. At
outlet temperatures below about 600.degree. C. there is
insufficient reactivity to reduce the olefin and heavy hydrocarbon
content to acceptable levels. At outlet temperatures above about
860.degree. C. there is too much oxygen or in other words, more
than necessary and further, methane and other hydrocarbons will be
oxidized to carbon oxides, hydrogen and water to reduce the heating
value of product stream 14 and therefore, its usefulness as a
fuel.
If the reaction takes place within the temperature limits discussed
above and the feed conditions of the reactant mixture, the oxygen
is totally consumed and the water is reduced to less than 15
percent by volume at the outlet of the partial oxidation reactor
12. Under such conditions, saturated hydrocarbons in the feed will
react but at a slower rate than the olefins. The higher molecular
weight of hydrocarbons with more than two carbon atoms are also
converted into hydrogen, carbon monoxide, carbon dioxide and
methane. At the reaction conditions specified, the product stream
14 will contain less than about 0.5 percent olefins by volume on a
dry basis and less than about 10 percent by volume on a dry basis
of alkanes with two or more carbon atoms. At such temperatures,
other hydrocarbons may exist but in trace amounts and in any case
less than about 1 percent by volume on a dry basis. The remaining
content will comprise methane, hydrogen, carbon monoxide, carbon
dioxide and water vapor. Such a treated product stream 14 is
suitable for use in part or alone as a fuel for gas turbine 20.
Catalytic partial oxidation reactor 12 contains a partial oxidation
catalyst which is preferably a metallic monolith coated with a
catalytic layer that contains platinum, rhodium, palladium, nickel
or ruthenium. The structure of the monolith can be reticulated
foam, honeycomb or a corrugated foil wound in a spiral
configuration. Catalyst coated ceramic beads or ceramic monoliths
in the form of reticulated foam or honeycomb structure are other
possibilities.
It is believed that the metallic supported catalyst has better
performance than other supported catalysts in that it has better
heat conductivity, a more uniform temperature profile than other
catalyst forms and a lower operating temperature. All of these
factors permit the more selective destruction of olefins without
converting too much of the paraffins for instance, ethane, into
olefins.
A useful catalyst can be obtained from Sud Chemie of Louisville,
Ky., USA which is in the form of a monolith which is sold as PC-POX
1 on FECRALY. Experimental data has confirmed that space velocities
of about 46,000 hours.sup.-1 are effective for the reactive mixture
with such catalyst to produce a product having olefin and other
hydrocarbons with more than 2 carbon atom contents that are
acceptable for use within a gas turbine. For such purposes, space
velocity is defined as the ratio of the volumetric gas flow rate at
standard temperature and pressure divided by the empty reactor
value. Practically, longer residence time may be recorded and
hence, space velocities of at least 10,000 hours.sup.-1 may be
required for certain feeds to be treated.
In order to operate any embodiment of the present invention,
preliminary water to carbon and oxygen to carbon ratios and desired
outlet temperatures to be obtained can be determined by known
simulation techniques for a given feed. The makeup of the feed can
be determined by gas chromatography. Finer adjustments to such
ratios, feed rates and etc. can be made in the field by analysis of
product stream 14. Such finer adjustments can involve sampling and
analyzing product stream 14 using gas chromatography. Preferably,
sufficient data can be developed so that performance could be
predicted without analysis by gas chromatography. There are
possible applications for the present invention in which product
stream 14 is used as the sole fuel to the gas turbine 20. This
would of course depend on its heating value and compatibility with
the gas turbine combustor 28. In most cases, product stream 14 will
be used as an adjunct and therefore, blended with another fuel
stream, for instance natural gas stream 16. However, since
potential coking hydrocarbons have been controlled to levels
similar to those found in natural gas, such treated streams as
product stream 14 can be used in greater amounts than contemplated
in the prior art.
As mentioned above, gas turbines can be designed to run on process
gases, such as coke oven gases, provided the heavier hydrocarbons
are removed by scrubbing. High levels of higher molecular weight
hydrocarbons, especially olefins, can form carbon within gas
turbine combustors and result in erosion and fouling of gas turbine
components and the emission of "smoke" in the gas turbine
exhaust.
The amount of variation of the heating value for a given fuel
system design is however limited. Fuel nozzles are designed to
operate within a specific volumetric flow rates. Ranges in heating
values can be accommodated by increasing or decreasing the fuel
nozzle area or gas temperature. For an existing combustor designed
for a fuel such as natural gas the fuel nozzle area is fixed. The
temperature of the fuel can be adjusted to keep fuel stream 18
within the desire energy density for gas turbine control purposes.
A measure of the inter-changeability of gas fuels for a given
system design is the Wobbe Index. The Wobbe Index is equal to a
ratio of the lower heating value of the fuel and the square root of
a product of the specific gravity of the fuel relative to air and
the temperature of the fuel. Typically, the fuel is supplied at a
temperature that does not exceed plus or minus 5 percent of the
Wobbe Index.
Therefore, in retrofit situations or situations in which the gas
turbine is not modified, product stream 14 or a blend including
product stream 14, for example fuel stream 18, is utilized in a
manner to meet the design Wobbe Index of a particular gas turbine
combustor. The degrees of freedom that will govern the use of
product stream 14 are its composition and temperature and if
blended, the composition and temperature of the blend or for
example, fuel stream 18. In a situation in which product stream 14
is to be used alone, its temperature can be adjusted through heat
exchange with reactant streams for catalytic partial oxidation
reactor 12 and if necessary, by further cooling. In case of
blending, further or the sole temperature control may be obtained
by controlling flow rates of the product stream 14 and the other
fuel stream, for instance, natural gas stream 16. The lower heating
value of the blend can also be controlled by controlling flow
rates.
In practice, the composition of the hydrocarbon containing feed
stream 10 may vary to in turn vary the composition and temperature
of product stream 14 and therefore any calculated Wobbe Index. As
indicated above, if the composition and temperature of product
stream 14 is controlled, then control of the blending of the
streams is a simple and straight forward matter of controlling the
flow rates of the two streams. In most operational situations the
use of catalytic partial oxidation will dampen feed variations in
that such a reaction preferably removes heavier hydrocarbons which
are the most likely variables in the feed. Hence, generally, all
that is required is to control the temperature of the blend once a
blend ratio is selected by use of the turbine fuel preheat
controls.
If further control is required due to variability in the
composition of hydrocarbon containing feed stream 10, a finer
degree of control can be obtained limiting the amount of product
stream 14 that is blended with natural gas stream 16 to less than
about ten percent. This of course may be the least desirable course
of action. A more desirable control is to dampen feed variations by
operating catalytic partial oxidation reactor 12 with a slightly
higher oxygen to carbon ratio than the minimum required to maintain
olefins at less than 0.5 percent and other hydrocarbons with more
than two carbon atoms less than 10 percent. The excess oxygen for
such purposes can be between about 10 percent and about 15 percent
higher than the minimum amount required. This is sufficient to
control a 20 to 30 percent increase in composition of a single
component, for instance ethylene, in the feed gas.
In addition, it is important to control the quantity of fuel
delivered to the gas turbine to match the fuel requirements for a
given gas turbine operating condition. This can be accomplished by
monitoring the composition of hydrocarbon containing stream 10,
again by gas chromatography, and using the results of such
monitoring to set the flow rate to match the gas turbine
requirements. Such operation of the catalytic partial oxidation
reactor 12 will essentially dampen feed variations so that they do
not result in substantial differences in the Wobbe Index and the
gas turbine fuel requirements can be consistently delivered.
A yet further strategy for controlling the reaction within
catalytic partial oxidation reactor 12 in response to feed
variations is to adjust the oxygen to carbon ratio and the steam to
carbon ratio so that the exit temperature of catalytic partial
oxidation reactor 12 is maintained within a very narrow window.
Maintaining the temperature in a narrow window will result in a low
variability of composition within product stream 14. Feed variation
can result in more or less carbon being present in the hydrocarbon
containing feed 10. If the carbon content in the hydrocarbon
containing feed 10 increases, if for example, the feed ethylene
concentration increases, and no corrective action is taken then the
temperature of product stream 14 will decrease. The opposite will
happen if the carbon content in hydrocarbon containing feed stream
10 decreases. Temperature variations will lead to composition
fluctuations, which will effect the temperature and the heating
value of the product stream 14 which will then be blended with
turbine natural gas stream.
Practically, in order to maintain the steam to carbon and oxygen to
carbon ratios constant, the flow rate of the hydrocarbon containing
feed stream 10 can be controlled. For instance, if the carbon
concentration of the feed increases, the flow of the hydrocarbon
containing feed stream 10 can be decreased, for example, by a
control valve, in order to keep the carbon to oxygen ratio and the
steam to carbon ratio the same and ultimately the temperature of
product stream 14 in the desired range. This action will counter
the temperature decrease that the higher carbon feed concentration
would have so that the temperature would remain within the narrow
window. Maintaining the temperature within 5 to 15 degrees of a set
point is sufficient. The set temperature point to be maintained is
determined on a case by case basis since it will depend on the
average composition of hydrocarbon containing feed stream 10 and as
mentioned above will be between about 600.degree. C. and about
860.degree. C.
As can be appreciated by those skilled in the art, a combination of
the different control schemes could be utilized. Further, such
combination or any of the control schemes mentioned above could be
manually implemented in that practically, feed variations occur
over a sufficiently long period of time. Automated control is of
course possible.
With reference to FIG. 2, an alternative embodiment of FIG. 1 is
illustrated that has the advantage of preheating combined stream 38
while reducing the temperature of product stream 14 to acceptable
levels and to help meet the Wobbe Index of the combustors 28 and
thereby to enhance the degree to which product stream 14 can be
utilized as makeup for fuel stream 18. As illustrated, a heat
exchanger 46 preheats combined stream 38 while cooling product
stream 14. The preheated combined stream 38 has the additional
advantage of lowering the required oxygen usage to maintain reactor
exit temperature and maintain the appropriate hydrocarbon
content.
With reference to FIG. 3, an alternate temperature control is
provided by pumping a makeup water stream 48 formed of de-ionized
water ("DI") with a pump 50 to produce a pressurized stream 52 that
is at a sufficient pressure to be introduced into a quench tower 54
("Quench") along with product stream 14. As a result, product
stream 14 will be at a lower temperature upon its combination with
natural gas stream 16 and will contain water vapor that will tend
to lower NOx emissions of gas turbine 20 and provide slightly more
mass to be expanded in turbine section 32. The oxygen containing
stream in this embodiment, as well as any embodiment, can be an air
stream 56 that is compressed by a compressor 58 to produce a
compressed air stream to serve as the oxygen containing stream 36.
Oxygen containing stream 36 is introduced along with hydrocarbon
containing feed stream 10 and steam stream 34 into catalytic
partial oxidation reactor 12.
Compression of air stream 56 is required since, as indicated above,
steam stream 34 and hydrocarbon containing feed stream 10 are
obtained at pressure. Since the heat of compression is not removed
from compressed air stream forming the oxygen containing stream 36,
it can help supply heat to the reactant mixture to be consumed
within catalytic partial oxidation reactor 12 to help reduce oxygen
utilization.
FIG. 4 illustrates an embodiment of the present invention in which
a makeup water stream 62 is pumped by pump 64 to produce a
pressurized stream 66 that is of a sufficient pressure that when
introduced into a boiler 68 or other heat exchange device, steam
stream 34 will be at a sufficient pressure to in turn be combined
with hydrocarbon containing stream 10. The resulting combined
stream 38 is introduced into catalytic partial oxidation reactor
12. Product stream 14 indirectly exchanges heat with pressurized
stream 66 within boiler 68 to raise the steam and as a result cool
to form a partly cooled product stream 14a. The partly cooled
product stream 14a is then further cooled within heat exchanger 72
to produce a cooled product stream 14b that is combined with
natural gas stream 16. At the same time, an air stream 74 is
compressed by a compressor 76 to produce a compressed air stream 78
that is heated within heat exchanger 80 against the cooling of
partly cooled product stream 14a to produce oxygen containing
stream 36 that is heated and thereby can serve to heat the reactant
mixture to be reacted within catalytic partial oxidation reactor
12.
FIG. 5 illustrates an alternative embodiment of FIG. 3 in which a
bleed air stream 26a is extracted from compressor stream 26. Bleed
air stream 26a is then further compressed by compressor 58 and
introduced directly into catalytic partial oxidation reactor 12.
This embodiment helps reduce the compression duty of the separate
compression provided by compressor 58.
It is to be noted that the combustors 28 can be diffusion
combustors or lean premix combustors also known as dry low NOx
combustors. In diffusion combustors, the fuel/air mixing and
combustion take place simultaneously in a primary combustion zone.
In lean premix combustors the fuel and air are mixed in an initial
or primary mixing stage. The resultant mixture is then fed into a
secondary combustion stage where combustion takes place. There are
a variety of known air and fuel staging techniques that are
utilized in such combustors. Lean premix combustors are
particularly sensitive to the hydrogen content and compositional
variations of the fuel and the use of fuels with a hydrogen content
at or above about ten percent by volume is problematical in such
combustors.
With reference to FIG. 6, a further alternative embodiment is
illustrated that is particularly suited for use with a lean premix
combustor 28' where the hydrogen content of the product stream 14
is ten percent and greater. The illustrated embodiment is somewhat
similar to that illustrated in FIG. 3 except that the natural gas
stream 16 is co-currently passed through a heat exchanger 84 that
acts to cool product stream 14 while warming natural gas stream 16.
As will be further discussed, natural gas stream 16 and product
stream 14 are separately fed to lean premix combustor 28'.
With reference to FIG. 7, lean premix combustor 28' is provided
with a primary mixing zone 86 in which air and fuel mix proportions
that dilute the fuel. The fuel is combusted within a secondary
combustion zone 88 and cooled within a cooling zone 90. Lean premix
combustor 28' is provided with a combustion liner 92 having slots
94 for introduction of air in the direction of the arrowheads. Part
of the compressed air stream 26 enters lean premix combustor 28' as
a stream "A" and typically, another part "B" is used for cooling
purposes. Natural gas stream 16 is introduced into the primary fuel
nozzles 92. The product stream 14 is introduced into secondary fuel
nozzle 94 where the hydrogen content of the stream is not
particularly sensitive.
As mentioned above, combustors 28 could be lean premix combustors
such as lean premix combustor 28' with parts of fuel stream 18
being introduced both into primary fuel nozzle 92 and secondary
fuel nozzle 94. Furthermore even in a case of product stream 14
having an unsuitably high hydrogen content, at and above about ten
percent, blending product stream 14 with natural gas stream 16
could lower the hydrogen content of fuel stream 18 on a volumetric
basis to allow such a blended stream to be injected in both the
primary and secondary fuel nozzles 92 and 94 respectively.
A calculated example was performed for a typical lean premix
combustor designed to operate with a natural gas fuel at a gas
temperature of about 204.degree. C. This calculated example will be
discussed with respect to the embodiment of the present invention
illustrated in FIG. 2.
The natural gas composition is given in the Table set forth below.
The catalytic partial oxidation reactor 12 was simulated as a Gibbs
reactor. The Wobbe Index of the natural gas at 100.degree. C. is
about 45.625 calculated by conventional means. As indicated above,
a gas turbine can accept as gas with a Wobbe Index within 5 percent
of the design value or in the range of between about 43.343 and
about 47.907 in case of natural gas at the aforesaid
temperature.
In the example, hydrocarbon containing feed stream 10 is formed of
a typical refinery offgas produced by a fluidic catalytic cracker.
Hydrocarbon containing feed stream 10 has a composition given in
the Table, set forth below, and a flow rate of about 25 percent of
the natural gas stream 16 volumetric flow rate. Steam stream 34,
having a flow rate of about 10 percent of hydrocarbon containing
stream 10 volumetric flow rate and a temperature of about
250.degree. C., is mixed with the hydrocarbon containing feed
stream 10 to produce combined stream 38 which is in turn fed to
catalytic partial oxidation reactor 12 that operates at a pressure
of about 300 psig. An oxygen containing stream 36 of substantially
pure oxygen which has a flow rate that is about 7 percent of
hydrocarbon containing stream 10 volumetric flow rate and a
temperature of about 21.degree. C. is also introduced into
catalytic partial oxidation reactor 12.
The temperature of the product stream 14 is calculated at
720.degree. C. and has a composition also set forth in Table 1.
Product stream 14 is cooled in heat exchanger 46 and mixed with
natural gas stream 16 having a temperature of about 20.degree. C.
to produce the fuel stream 18 to be fed as fuel into combustors 28.
The composition of the fuel stream 18 is listed in the far column
of Table 1. Fuel stream 18 is controlled to a temperature of about
80.degree. C., which would be above the condensation point for
water in such stream and would possess a calculated Wobbe Index of
43.557, which is in the range of the natural gas Wobbe Index limits
set forth above. As can be appreciated, such calculation could be
used as a measure of the preliminary adjustment to the steam and
oxygen to carbon ratios mentioned above.
TABLE-US-00001 TABLE Natural Hydrocarbon Gas Containing Stream Feed
Product Fuel 16 Stream 10 Stream 14 Stream 18 Hydrogen Mol % 0
10.833 4.245 1.117 Methane mol % 91.78 37.705 67.974 85.517
Ethylene mol % 0 15.907 0.073 0.019 Ethane mol % 3.42 15.509 0.203
2.574 Propylene mol % 0 2.835 0.006 0.001 Propane mol % 0.61 1.647
0.002 0.450 Isobutane mol % 0.07 0.678 0 0.052 n-Butane mol % 0.1
0.197 0 0.074 1-Butene mol % 0 0.15 0 0 1,3-Butadiene mol % 0 0.007
0 0 Isopentane mol % 0 0.277 0 0 Pentane mol % 0.05 0.836 0 0.037
1-Pentene mol % 0 0 0 0 Hexane+ mol % 0.03 0 0 0.022 N2 mol % 3.23
9 6.302 4.038 O2 mol % 0 0.017 0 0 CO mol % 0 2.146 20.852 5.486
CO2 mol % 0.71 2.256 0.3 0.602 H2O mol % 0 0 0.043 0.011 Total
100.000 100.000 100.000 100.000 Molecular 17.4 22.83 18.82 17.78
weight Lower heating 916.36 1046.5 703.41 860.29 value
BTU/ft.sup.3
While the present invention has been described with reference to a
preferred embodiment, as will occur to those skilled in the art,
numerous changes, additions and omissions can be made without
departing from the spirit and the scope of the present
invention.
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